1. Field of the Invention
This invention relates generally to seismic systems, and more particularly to seismic systems used in the hydrocarbon exploration and mining industries. Specifically, this invention relates to a system and method for transmitting data from remote measuring stations in a vertical seismic profiling or cross-well seismic profiling toolset.
2. Description of the Prior Art
Measuring seismic data in boreholes has origins which can be traced back to 1917, where the technology was introduced in U.S. Pat. No. 1,240,328 issued to Fessenden. Because of the widespread preference for surface-recorded seismic surveys, borehole seismic recording has often been limited to the velocity check-shot survey, a method used to determine seismic velocities over various intervals in the well for interpretation of surface recorded seismic data.
A typical check shot survey involves lowering a geophone or hydrophone into a well to a selected position and measuring the time for an acoustic pulse at the surface to travel to the receiver. Receivers are often simple pressure transducers and are incapable of detecting the polarity and amplitude of a waveform in three dimensions. Receiver locations are generally separated by hundreds of vertical feet. The recording window is long enough to record only the directly arriving signals; wave reflections and total borehole response are not recorded. The check-shot provides a direct correlation between subsurface stratigraphy and seismic reflections measured at the surface, and it allows surface seismic data recorded in the time domain to be converted to lineal depth.
However, in the last twenty-five years interest has grown in more comprehensive borehole-recorded seismic surveys, such as vertical seismic profiling (VSP). As illustrated in FIG. 1, VSP is the recording of seismic energy from a surface source (10) by geophones (12) in a well or borehole (14) to obtain a high resolution image of the subsurface geology adjacent to the borehole. Because the downhole receivers record direct arrival waves (16), VSP images are higher in resolution than surface seismic images which are generated only by reflected, attenuated waves. VSP can provide in situ rock properties, particularly seismic velocity, impedance, anisotrophy, and attenuation, and it aids in understanding seismic wave propagation, e.g., source signatures, multiples, and conversions.
FIG. 1 shows the basic components of a VSP survey: a surface-based seismic source (10), a downhole receiver array (18) of sensors (12), and a surface-based recording/wireline truck (20) or other recording means. The lateral distance from the surface source to the well is referred to as “offset” (22). Zero-offset VSP, in which the shot is located near the well, provides a seismic time-to-depth relationship, interval velocities in depth, and a normal-incidence reflectivity trace. Offset VSP, in which the shot is a further distance from the well, allows for the imaging of the subsurface away from the well. When a series of offset VSP surveys are conducted, with sources positioned along a line radiating outward from the well at varying offsets, it is referred to as a walk-away VSP. Walk-away VSP creates a two-dimensional reflectivity image away from the well. Three-dimensional vertical seismic surveys can also be conducted using a full areal set of shots on the surface. A related downhole seismic survey is cross-well profiling (CWP), in which a VSP receiver array is placed in a first borehole while the seismic source is lowered into a second borehole and emitted therefrom.
VSP uses a number of downhole geophones (12) in the receiver array (18), usually at a regular spacing interval of 50 to 100 feet. Single component receivers, such as vertical axis geophones or hydrophones, may be free-hanging in the array, but multiple-component receivers, such as triaxial geophones, must be clamped to the borehole wall in order to couple to the wave in all three dimensions. A common prior art VSP receiver array (18) configuration has receiver pods (12), with three-component geophones, deployed at five depth levels, as illustrated in FIG. 1. The triaxial geophones are connected with standard seven-conductor wireline logging cables (24) and are located in pods (12) designed to clamp to the borehole wall.
In practice, the receiver array (18) is usually lowered to the bottom of the well (14), clamped to the borehole sides, and then set to record a surface-generated source shot or shake. The collected data is transmitted to the recording truck (20) via the wireline cable (24). The tool (18) is then unclamped from the borehole sides, moved its length up the hole, and re-clamped; the source (10) is reactivated and measured. This sequence continues up the hole (14) to capture the entire vertical profile. VSP surveys can be conducted in open as well as cased holes, but cased holes are often preferred because they allow the use of magnetic clamping tools and avoid borehole stability problems.
FIG. 2 illustrates an enlarged view of a portion of the prior art borehole seismic recording system of FIG. 1. The system includes a surface-based controller (20) connected to a downhole telemetry module (21), which in turn is connected to one end of a string (18) of remote sensor pods (12). The string (18) is lowered into a borehole (14) and suspended by a winch or hoist (15). Each pod has a clamping mechanism (26) to mechanically couple the pod to the borehole wall. The pods (12) are typically hard-wired into the array (18) and have over-molded connections to the cable (24). Thus, the array configuration is generally fixed; it is not possible to change the configuration at the job site, and field repairs are limited.
It is advantageous to record measurements over the whole vertical range of the well to provide the most complete depth and coverage, but it is also more costly. The cost of VSP or CWP depends on the number of depth levels recorded, the total vertical distance of the operation, the number and type of source offsets, time on site, tool rental costs, and mobilization/demobilization costs. Thus, increasing the number of receivers which can collect data in a given array or otherwise speeding up the process may reduce cost.
One major inefficiency of the borehole seismic process is the need for each downhole multi-component receiver to be clamped to the borehole wall. The clamping and unclamping process takes time. Free-hanging receiver arrays using only vertical geophones or free-hanging hydrophone strings with simple pressure transducers may be attractive choices for VSP or CWP; many receivers can be deployed with minimal effort, and considerable time is saved by avoiding repetitive clamping and unclamping. However, these receivers provide only single component data which limits subsurface imaging and seismic data extraction, because compression (P) and shear (S) data cannot be resolved. Additionally, because the receivers are free-hanging, borehole waves are a major source of noise. Although some of this noise can be removed with various filtering operations, free-hanging sensors do not image as deep as their clamped-geophone counterparts.
The current trend is to record data with three-component geophones which allow three-component data processing techniques used to discern the different wave arrivals, such as P, SV, and SH, for improved seismic interpretations. Cost reduction of borehole seismic surveys using clamped geophones is gained by increasing the number of depth layers on the toolsets. The greater number of levels which can be measured at one time, the fewer times the array must be moved to cover the vertical depth of the well.
As borehole seismic technology matures, the amount of data collected increases. Higher signal resolution, a greater number of depth layers in the arrays, the use of 3-C geophones, and increases in the recording time to capture multiple wave reflections all enlarge the amount of the data which must be sent to the surface recorder. Often, a downhole telemetry module (21) is coupled between the surface recorder (20) and the array (18). The telemetry module may contain power supply circuitry and motor controller/driver circuitry for the pods (12) and a large memory buffer to temporarily store data transmitted from the pods. The telemetry module may also contain an anchor (23) and an optional gamma ray emitter. The telemetry module may be used to shorten the distance and time for data transfer from the pods by receiving the pod data and storing it within a large memory buffer for later transfer to the surface-based main controller.
Although some systems employ cabling with enough analog wire pairs to accommodate a large number of three-component receiver stations, most systems continue to use standard seven-conductor wireline cable. The cable often includes strength members which support the weight of the sensor array. The large capital invested in seven-conductor cable and equipment may make a transition to another cable type cost prohibitive.
Thus, VSP and CWP often use semi-intelligent receiver pods which digitize the measured analog seismic waveforms and store the data in a buffer (28), as shown in FIG. 2. Although each of the sensor pods (12) can be directly wired to the downhole telemetry module more commonly the pods (12) are coupled to the telemetry module (21) using a common databus (30). Each memory buffer (28) is tied to the bus (30) with a driver capable of driving the bus. Generally, the system is arranged so that only one pod drives the bus at a time. The seven-conductor wireline cable (24) contains a coaxial cable used as a databus (30) to which each buffered receiver pod is multiplexed. Receivers, in sequential fashion, send their stored data to the telemetry module (21) along the common databus (30) after the seismic event has occurred.
FIG. 3 is a schematic diagram in block level detail showing the electronic circuit of one type of prior art receiver pod (12). The receiver is powered by a power supply (58) which is tied to a power bus (60) that is independent of the data bus (30). The receiver pod (12) has a sensor (50) whose output is digitized and stored in a memory buffer (28). In this example, the buffer (28) is connected to a common databus (30), shared by all receiver pods in the array (18) (See FIG. 2), by a transmitter (52) and an analog double-throw switch (54). When the pod (12) is driving the bus (30), switch (54) connects the upper portion (30A) of the bus to the transmitter (52) and disconnects the lower portion (30B) of the bus. When the pod (12) is not driving the bus (30), it is disconnected by switch (32). The analog switch (54) is controlled by an addressing circuit (56) and control lines (57). The transmitter (52) must be designed to transmit the signal to the telemetry module, which can be a significant distance.
Referring back to FIG. 2, the databus cable (30) must be long enough to extend from the telemetry module (21) to the most remote receiver, POD N, at the bottom of the well. The long length reduces the available bandwidth of the databus. The most remote pod is the most affected by the limited bandwidth. One at a time each pod will transfer its data directly to the telemetry module. For example, POD 1 will transfer the contents of its buffer (28) to the telemetry module (21) in time t1, then POD 2 will transfer directly to controller (20) in time t2, etc., until POD N completes the cycle by transferring its collected data in time tN. Time tN is substantially greater than time t1. The total time for all of the data stored in the array (18) of N sensors to be transferred to the telemetry module (21) is the summation of the individual transfer times t1 . . . tN, which can be significant in arrays with a large number of pods or having a long distance to the telemetry module.
As the number of receivers continues to rise, the large data volumes which must be transmitted to the receiver before the array can be repositioned, bottlenecked by the insufficient bandwidth of the databus, becomes significant. A high capacity datalink is desirable. Some systems have explored the use of a fiber optic cable for a databus. In addition to the obstacle of overcoming the inertia of the capital investment in seven-conductor wireline cable, as discussed earlier, fiber optics are problematic from a materials standpoint because of the high downhole temperatures encountered.
3. Identification of Objects of the Invention
A primary object of the invention is to provide a method and system for improved borehole seismic measurement by improving data transfer rates between the downhole components in an array of intelligent sensors.
Another object of the invention is to provide a method and system to communicate with each sensor in the seismic array and power each array sensor using a shared conductor pair. Sensor control and power may originate from either a downhole telemetry and control module or a surface-based controller.
Another object of the invention is to provide a method and system to selectively allow a concurrent trigger pulse to all sensors in the array to promote synchronous recording and sampling by the sensors.
Another object of the invention is to provide a method and system to send data acquisition and control parameters and commands to each of the sensor pods by the bucket brigade method, starting from the telemetry and control module.
Another object of the invention is to provide a method and system for a seismic array having a varying number or type of sensors located therein, the sensors having connectors to allow interconnection in varying numbers and with varying lengths of cable, thus allowing easy configuration changes and array repair in the field.
Another object of the invention is to provide a method and system for an intelligent sensor array which can determine its current configuration by using either the telemetry and control module or the surface controller to sequentially query each sensor pod in the array to determine the capabilities and location within the sensor array and also to assign a temporary identification number to each sensor pod.
Another object of the invention is to provide a method and system for a downhole sensor array of up to 200 clamping receiver pods each equipped with 3-C sensors.